Fractured Reservoir Research Articles

Effect of bedding planes and property contrast between layers on the propagation mechanism of hydraulic fracture height in shale reservoirs

Bedding planes and property contrast between layers plays an important role in preventing hydraulic fracture height extension in shale reservoirs. However, the intrinsic causes of fracture containment have not been elucidated, and few studies have considered the effects of mixed factors on fracture height extension. Based on the continuum-discontinuum element method, a 3D hydraulic-mechanical coupling model was established to explore the influence mechanism of bedding planes, stress and modulus difference between layers, and mixing factors on fracture height extension in a transversely isotropic shale reservoir. Shear failure usually occurs preferentially when the fracture approaches the bedding plane, and the essential reason for fracture containment is that the shear slip on the bedding plane blunts the fracture tip. The stronger stress barrier formed by the higher minimum principal stress in adjacent formation effectively enables the fracture to terminate at the interlayer interface. The lower modulus in adjacent formation is more prone to rock initiation, but the larger elastic deformation absorbs the fracture tip stress and impedes height propagation. The comprehensive effect of bedding planes and property contrast between layers on fracture propagation is more complex than that of a single factor. When different factors have positive effects on fracture containment, the fracture is easier to terminate at the bedding plane. Otherwise, the dominant factor determines whether the fracture can be captured. No matter what the conditions, the pressure relief in the bedding plane can slow down the propagation rate. The findings can offer theoretical support for predicting fracture height during field fracturing in shale reservoirs.

Research and Application of Temporary Blocking and Diversion Techniques for Fractures in Tight Oil Reservoirs

Research and Application of Temporary Blocking and Diversion Techniques for Fractures in Tight Oil Reservoirs

Characteristics and effectiveness of deep and ultradeep tight sandstone fractures: Insights from geologic and geophysical data analysis

Effective natural fractures are those that contribute to reservoir storage and conductivity. In this study, the effectiveness of fractures in deep and ultradeep reservoirs (depths > 6 km) is evaluated by using geophysical image logs, cores, microstructures, mechanical tests, and geologic evidence of the tectonic context (including current in situ stress) and sedimentary faces and diagenesis. Intraformational open-mode fractures are the most common fracture type in this tectonically active region, and their effectiveness is affected by the coupling between past tectonic activity, in situ stress, and chemical reactions such as mineral precipitation or dissolution (diagenesis). Our results show that the effectiveness of fractures is mainly related to the aperture and filling, and fractures formed by early tectonic movement are more likely to be filled by minerals, reducing their effectiveness. Strata near orogenic belts in strongly cemented, tight diagenetic facies exhibit a greater abundance of mineral-filled fractures, whereas dissolution increases the fracture apertures, produces secondary pores in host rocks, and roughens the fracture walls. The effective normal stress acting on the fracture surface decreases when the fracture is parallel to the maximum horizontal stress component, so the fracture has a large aperture and, therefore, is more effective. The results of our laboratory measurements reveal that the contribution of fractures to the reservoir space is limited, and the reservoir space provided by fractures accounts for only 13% of all types of reservoir space, whereas the presence of fractures increases reservoir permeability by 1–2 orders of magnitude. Fractures improve the effectiveness of the reservoir by connecting the dispersed pores in the reservoir matrix. Fractures with a low angle to the maximum horizontal stress component have greater apertures and permeabilities and are the main channels for fluid flow.

The in situ stress prediction of a fractured shale reservoir based on amplitude variation with angle and azimuth inversion: A case study from Southwest China

In situ stress estimation of a shale reservoir is critical for the design of shale hydraulic fracturing and wellbore stability analysis. Fractured shales have orthogonal anisotropy (OA) because of the presence of vertical fractures and lamination. However, the existing in situ stress estimation method mainly focuses on transversely isotropic media. To accommodate orthogonally anisotropic media, an in situ stress estimation method is developed by using amplitude variation with angle and azimuth inversion and linear-slip theory. First, an orthogonal anisotropic medium is introduced to characterize the fractured shale by using a linear-slip model, and then we formulate a reflection coefficient approximation for OA media to perform the seismic inversion. Next, a fracture weakness inversion strategy that incorporates the vertically transverse isotropic background is developed to obtain the stiffness matrix of the media. Finally, the in situ stresses of the OA medium are formulated by using a stress-strain relationship. Inversion tests and a real data application indicate that our method is effective.

Control of lamination on bedding-parallel fractures in tight sandstone reservoirs: the seventh member of the upper Triassic Yanchang Formation in the Ordos Basin, China

Control of lamination on bedding-parallel fractures in tight sandstone reservoirs: the seventh member of the upper Triassic Yanchang Formation in the Ordos Basin, China

Induced carbonate dissolution: Impact of brine chemistry in CO2 foam

Foam CO2might be considered an efficient alternative to reduce gas mobility and produce favorable mobility ratios. It offers significant advantages, particularly in heterogeneous or fractured reservoirs due to its ability to block highly permeable layers or divert the injected fluid from fractures into the matrix. In the present work, a surfactant solution made of different ionic compositions was co-injected into outcrop Edwards Limestone to determine the impact of brine chemistry on carbonate dissolution upon CO2foam injection. The development in differential pressures (DP) during continuous co-injection of sc-CO2 and different surfactant solutions (NaCl, NFB, CB) shows that unwanted chemical reactions (dissolution/precipitation) compromise the rock integrity by more acid formation and wormholing. Rock-fluid-foam interactions indicate that the total heat in the rock-fluid-foam systems is 6.9 mJ NaClfoam, 19.3 mJ NFBfoam, and 37.8 mJ CBfoam systems. On the other hand, the total heat for the fluid-foam interactions is 11.5 mJ NaClfoam, 12.5 NFBfoam, and 20.4 mJ CBfoam. The demicellization of the foam formulations could have led to calcite dissolution. The synergy between ITC and core flooding experiments elucidates the impact of the brine chemistry on calcite dissolution during foam-assisted CO2sequestration at both microscopic and macroscopic scales.

Host-Guest recognition strengthened supramolecular preformed particle gel for conformance control in low-permeability fractured reservoirs

The conventional preformed particle gels (PPG) have problems of irreversibly shear-breakage after shearing actions during the application for conformance control in low-permeability fractured reservoirs. Herein, a novel host–guest recognition strengthened supramolecular PPG (S-PPG) was synthesized with synergistically non-covalent and covalent crosslinking structures, using host (allyl β-CD) and guest (cetyldimethylallyl ammonium chloride) monomers. Firstly, the chemical structures and micro-morphologies of S-PPG were systematically characterized by FTIR, Cryo-SEM, EDS and AFM methods. Then, the dispersion and thermal stability, swelling properties and rheological properties, including viscoelasticity, creep-recovery and shear self-healing abilities, of S-PPG were investigated, respectively. Finally, the low-permeability cores with fractures were used to identify the injectivity and plugging properties of S-PPG and conventional PPG. The results showed that the S-PPG exhibited strong crosslinking network, high dispersion and thermal stability. In addition, the S-PPG also displayed better swelling, viscoelasticity, creep-recovery and shear self-healing ability after equilibrated swelling process compared to those of conventional PPG. Finally, the S-PPG exhibited considerable compatibility with low-permeability cores with fracture width of 0.05 mm, and produced higher plugging rate (93.53 %) than conventional PPG (86.35 %). Therefore, the newly formulated supramolecular preformed particle gel (S-PPG) containing host–guest recognition can provide a new approach for solving the problems of irreversibly shear-breakage and improving the conformance control performance of PPG in low-permeability fractured reservoirs.

The influence of lamination and fracture on the velocity anisotropy of tectonic coals

The elastic anisotropy of coal formations is important for the prediction of unconventional coalbed methane reservoir performance and hydraulic fracturing. Although essential for a number of geophysical applications, the elastic anisotropy of coals is still poorly understood. Therefore, three sets of cylindrical coal samples are drilled parallel and perpendicular to the bedding plane, and the ultrasonic velocities under different confining pressures are measured in the laboratory. We combine experimental observations and modeling analysis to evaluate the elastic anisotropy of the coals. The results suggest that the velocity of coals parallel to the bedding plane is less sensitive to the confining pressure than that perpendicular to the bedding plane. The fracture densities of coals parallel to the bedding plane are much lower than those perpendicular to the bedding plane, and most of the fractures are closed when the pressure is higher than 15 MPa. The organic matter and clay content and their preferred orientation play dominant roles in the velocity anisotropy, and the fracture effect can significantly enhance it. Velocity anisotropy parameters of coals are positively correlated with the organic matter and clay content, and the preferred orientation of organic matter and clay plays a significant role in coal anisotropy. The results in this study are helpful in the characterization of fractures of coals and can provide an important rock physics basis for microseismic fracture monitoring and reservoir prediction.

Deep-learning-based natural fracture identification method through seismic multi-attribute data: a case study from the Bozi-Dabei area of the Kuqa Basin, China

Fractures play a crucial role in tight sandstone gas reservoirs with low permeability and low effective porosity. If open, they not only significantly increase the permeability of the reservoir but also serve as channels connecting the storage space. Among numerous fracture identification methods, seismic data provide unique advantages for fracture identification owing to the provision of three-dimensional information between wells. How to accurately identify the development of fractures in geological bodies between wells using seismic data is a major challenge. In this study, a tight sandstone gas reservoir in the Kuqa Basin (China) was used as an example for identifying reservoir fractures using deep-learning-based method. First, a feasibility analysis is necessary. Intersection analysis between the fracture density and seismic attributes (the characteristics of frequency, amplitude, phase, and other aspects of seismic signals) indicates that there is a correlation between the two when the fracture density exceeds a certain degree. The development of fractures is closely related to the lithology and structure, indirectly affecting differences in seismic attributes. This indicates that the use of seismic attributes for fracture identification is feasible and reasonable. Subsequently, the effective fracture density data obtained from imaging logging were used as label data, and the optimized seismic attribute near the well data were used as feature data to construct a fracture identification sample dataset. Based on a feed-forward neural network algorithm combined with natural fracture density and effectiveness control factor constraints, a trained identification model was obtained. The identification model was applied to seismic multi-attribute data for the entire work area. Finally, the accuracy of the results from the training, testing, and validation datasets were used to determine the effectiveness of the method. The relationship between the fracture identification results and the location of the fractures in the target reservoir was used to determine the reasonableness of the results. The results indicate that there is a certain relationship between multiple seismic attributes and fracture development, which can be established using deep learning models. Furthermore, the deep-learning-based seismic data fracture identification method can effectively identify fractures in the three-dimensional space of reservoirs.

Characterization of natural fracture development in coal reservoirs using logging machine learning inversion, well test data and simulated geostress analyses

Natural fractures directly affect the permeability and mechanical strength of reservoirs, and their development degree has an important impact on the design and implementation of engineering and development projects. Although there is some correlation between logging data and fracture development, studies using algorithms to optimize logging predictions are still scarce. Meanwhile, there is a scarcity of calculations and analyses concerning the distribution of geostress at the block scale, and the pivotal role that geostress plays as a tectonic factor in the development of fractures. In this study, machine learning methods are used to predict reservoir fracture development, and regional geostress distribution patterns derived from well test data and finite element methods are combined for verification. The support vector machine (SVM), random forest (RF), extreme gradient boosting (XGBoost) and back propagation neural network (BPNN) algorithms are used to predict the fracture development of No.15 coal reservoir in the block. The results showed that the accuracy of SVM is 83.3 %, RF is 91.6 %, XGBoost is 93.7 % and BPNN is 95.8 %. The BPNN can effectively predict the reservoir fracture development of the block. Combined with the regional finite element stress-strain analysis and geostress measurement, the prediction of No.15 coal geostress distribution and fracture development model is established. Under comprehensive verification, the established distribution of the degree of regional fracture development under the control of geostress is consistent with the results of the BPNN prediction of fracture development. These results show that the regional geostress calculated in association with finite element analysis (FEA) can reflect the development of fracture in coalbed methane (CBM) reservoirs, and the neural network has good performance in predicting regional fracture development. This work provides a new approach to the application of machine learning in the field of geological engineering, and the comprehensively validated model provides geologists and geological engineers with ideas in algorithmic practice.

Investigation into the Variation Law of Network Fracture Conductivity in Unconventional Oil and Gas Reservoirs

The network fracturing technique is a key technology for increasing effective reservoir volume and enhancing production in shale oil and gas. The fracture network’s conductivity is one of the crucial factors affecting the efficient development of shale gas. To evaluate the variation patterns and influencing factors of the conductivity of network fractures, this study employed a proppant conductivity evaluation system and an equivalent theory testing method. It investigated the conductivity of propped and self-propped fractures under different angles and numbers of fractures. Experimental results showed that fractures with proppant support had higher conductivity than unsupported fractures. Smaller angles between secondary and main fractures resulted in greater conductivity. The conductivity of multi-fracture structures increased with the number of fractures. Under low-closure pressure conditions, self-propped fractures exhibited significantly higher conductivity than propped fractures, but this trend reversed under high closure pressure. This experimental research provides guidance for constructing network fractures with high conductivity in unconventional oil and gas reservoir fracturing.

Study on the influence of rock vertical heterogeneity on the vertical extension law of hydraulic fractures

The vertical expansion of fractures during hydraulic fracturing in low-permeability bottom-water oil and gas reservoirs is a crucial factor that significantly influences stimulation effectiveness. Fractures propagate concurrently in three dimensions; however, as operation time for fracturing and fracture length increase, there is a gradual reduction in fracture height. In the absence of a barrier layer or with inadequate strength and thickness, fractures may extend vertically or oscillate through it leading to an “unyielding” fractured state that impedes successful operations. This study introduces a mathematical model delineating the vertical expansion of hydraulic fractures (HFs) while computing stress intensity factors at upper and lower tips of each individual fracture. We use numerical methods to examine how vertical heterogeneity within reservoir rocks impacts laws governing vertical fracture propagation while conducting sensitivity analysis for making informed decisions on design parameters for hydraulic fracturing operations. The research results indicate that an escalation in stress disparity and increased toughness results in diminished height for HFs. Hydraulic fracturing augments fracture lengths along their respective axes. Nevertheless, if gap stress disparity surpasses net fluid pressure, a reduction in fracture length is observed. With an increasing ratio between local stress gradient versus fluid gravity gradient, HFs persistently advance vertically across cap and bed formations.

Chemical-Assisted CO2 Water-Alternating-Gas Injection for Enhanced Sweep Efficiency in CO2-EOR.

CO2-enhanced oil recovery (CO2-EOR) is a crucial method for CO2 utilization and sequestration, representing an important zero-carbon or even negative-carbon emission reduction technology. However, the low viscosity of CO2 and reservoir heterogeneity often result in early gas breakthrough, significantly reducing CO2 utilization and sequestration efficiency. A water-alternating-gas (WAG) injection is a technique for mitigating gas breakthrough and viscous fingering in CO2-EOR. However, it encounters challenges related to insufficient mobility control in highly heterogeneous and fractured reservoirs, resulting in gas channeling and low sweep efficiency. Despite the extensive application and research of a WAG injection in oil and gas reservoirs, the most recent comprehensive review dates back to 2018, which focuses on the mechanisms of EOR using conventional WAG. Herein, we give an updated and comprehensive review to incorporate the latest advancements in CO2-WAG flooding techniques for enhanced sweep efficiency, which includes the theory, applications, fluid displacement mechanisms, and control strategies of a CO2-WAG injection. It addresses common challenges, operational issues, and remedial measures in WAG projects by covering studies from experiments, simulations, and pore-scale modeling. This review aims to provide guidance and serve as a reference for the application and research advancement of CO2-EOR techniques in heterogeneous and fractured reservoirs.

Insight into the dynamic tensile behavior of deep anisotropic shale reservoir after water-based working fluid cooling

During deep shale gas production, flowing water-based working fluid inevitably cools shale reservoirs around boreholes and some fractures, and possible extraction methods induce dynamic stresses. To understand the dynamic tensile behavior of deep anisotropic shale reservoir after water-based working fluid cooling, a split Hopkinson pressure bar was used for performing the dynamic Brazilian tests on shale samples with bedding angles of 0°, 30°, 45°, 60° and 90° after reservoir temperature realization (25–200 °C) and water cooling. The results illustrate that dynamic tensile strength of shale samples decreases gradually as reservoir temperature increases under the loading rates 100–1000 GPa/s. From room temperature to 200 °C the most strength deterioration appears on samples with the bedding angle of 90°. A dynamic tensile strength deterioration model for deep shale reservoirs after water-based working fluid cooling is proposed considering the influence of loading rate and bedding angle. Geometrical trajectories of the main failure cracks are separated into three types, i.e., fully central tensile failure, tensile-shear failure and fully shear failure (sliding of bedding planes). For samples with bedding angles of 30°, 45° and 60°, increasing reservoir temperature encourages tensile failure to change into shear failure. The roles that bedding planes play in interacting with failure crack growth are summarized as IP mode (intersecting propagation), TP mode (turning propagation) and PP mode (promoting propagation). Anisotropic dynamic tensile strength responses are systematically discussed by using thermal stress simulation in ABAQUS, microstructure analyses, crack interaction conditions and the one-dimensional stress wave propagation theory. Based on experimental observations, field implications in borehole stability and fracturing of deep shale reservoirs are proposed under medium and high loading rates. This work is instrumental in providing valuable information and technology assistance for real deep shale gas production projects.

Resurgent dome and super-hot enhanced geothermal system: The Sahinkalesi Massif within the Hasandag Stratovolcanic Province, Central Anatolia, Turkey

The Sahinkalesi, a volcanic dome located NNE of Hasandağ, Türkiye exhibits anomalous heat flow value, geothermal gradient and the Curie point depth is located at very shallow depth in this region. Our investigation indicates presence of super-critical thermal regime (378°C) at about 4 km depth and the MT analysis indicate shallow magma chamber at about 5 km depth. The crust is relatively thin below this region with the low-velocity region located at depth of about 36 km. Thermo-Hydro-mechanical model investigation has been carried out using finite element discretization technique. For faulted zone reservoir models, 30 years of geothermal energy exploitation does not cause thermal breakthrough for mass flow rates up to 500 kg/s, however, the mean stress developed in the reservoir becomes much larger and may be unsustainable for the reservoir stability. To ensure the success of a fractured reservoir model, the use of multiple wellbores is recommended. In the case of a closed-loop geothermal system, the primary concern is the control of thermoelastic stress. This can be achieved either by increasing the wellbore depth while reducing the injection mass flow rate, or by extending the wellbore's horizontal component. The outlet temperature in both the cases maintained at 275°C. This is the first time a superhot EGS site has been identified in Türkiye.

Numerical Simulation of Non-Darcy Flow in Naturally Fractured Tight Gas Reservoirs for Enhanced Gas Recovery

In this work, we analyze non-Darcy two-component single-phase isothermal flow in naturally fractured tight gas reservoirs. The model is applied in a scenario of enhanced gas recovery (EGR) with the possibility of carbon dioxide storage. The properties of the gases are obtained via the Peng–Robinson equation of state. The finite volume method is used to solve the governing partial differential equations. This process leads to two subsystems of algebraic equations, which, after linearization and use of an operator splitting method, are solved by the conjugate gradient (CG) and biconjugate gradient stabilized (BiCGSTAB) methods for determining the pressure and fraction molar, respectively. We include inertial effects using the Barree and Conway model and gas slippage via a more recent model than Klinkenberg’s, and we use a simplified model for the effects of effective stress. We also utilize a mesh refinement technique to represent the discrete fractures. Finally, several simulations show the influence of inertial, slippage and stress effects on production in fractured tight gas reservoirs.

Research on Horizontal Well Multi-Fracture Propagation Law under the Synergistic Effect of Complex Natural Fracture and Reservoir Heterogeneity

Conventional fracturing design generally only considers the propagation of a single fracture in homogeneous storage, but the heterogeneity characteristics of the reservoir and the development of complex natural fractures will affect the fracturing effect. In order to study the horizontal well fracture propagation law under the synergistic effect of complex natural fracture reservoir heterogeneity, the globally embedded cohesive element finite model is established, and the heterogeneous reservoirs are built by Python programming. The influencing factors of multi-fracture propagation with heterogeneous reservoirs are analyzed, including the in situ stress difference, the injection rate of fracturing fluid, the perforation spacing, and the perforating clusters number. The results show that the heterogeneity and the natural fracture of the reservoir will affect the in situ stress distribution and propagation direction. When the in situ stress difference is low, the reservoir heterogeneity and natural fractures have a great influence on the fracture morphology. With the increase in injection rate, the fracture length and fracture width increase. With the in situ stress difference increase, the fracture deflection angle decreases. With the increase in fracturing fluid injection rate, the fracture length increases. The number of hydraulic fractures communicating with natural fractures increases with the natural fracture number and the number of perforation clusters under the synergistic effect of complex natural fracture and reservoir heterogeneity.

Evaluation of Key Development Factors of a Buried Hill Reservoir in the Eastern South China Sea: Nonlinear Component Seepage Model Coupled with EDFM

The HZ 26-B buried hill reservoir is located in the eastern part of the South China Sea. This reservoir is characterized by the development of natural fractures, a high density, and a complex geological structure, featuring an upper condensate gas layer and a lower volatile oil layer. These characteristics present significant challenges for oilfield exploration. To address these challenges, this study employed advanced embedded discrete fracture methods to conduct comprehensive numerical simulations of the fractured buried hill reservoirs. By meticulously characterizing the flow mechanisms within these reservoirs, the study not only reveals their unique characteristics but also establishes an embedded discrete fracture numerical model at the oilfield scale. Furthermore, a combination of single-factor sensitivity analysis and the Pearson correlation coefficient method was used to identify the primary controlling factors affecting the development of complex condensate reservoirs in ancient buried hills. The results indicate that the main factors influencing the production capacity are the matrix permeability, geomechanical effects, and natural fracture length. In contrast, the impact of the threshold pressure gradient and bottomhole flow pressure is relatively weak. This study’s findings provide a scientific basis for the efficient development of the HZ 26-B oilfield and offer valuable references and insights for the exploration and development of similar fractured buried hill reservoirs.

Quantification of the effect of fracturing on heterogeneity and reservoir quality of deep-water carbonate reservoirs

The Shiranish Formation represents one of the most important fractured reservoirs in northern Iraq. In this work, the petrophysical properties of the formation have been fully characterised using microscopy, core analysis, and well log analysis using conventional methods as well as new quantitative diagenetic approaches. During this work we have developed methods to quantify a petrophysical heterogeneity index (χ), reservoir quality indicator (RQI), and fracture effect index (FEI) for each of the stratigraphic units of the formation. The FEI was calculated by dividing the difference between the mean permeability of the wireline log data and the mean permeability of the unfractured core plug samples by the difference between the mean porosity of the wireline log data and the mean porosity of the unfractured core plug samples. This study shows that the Shiranish Formation has a fracturing pore system in all the characterised units, but it is particularly well developed in U.4, which shows the best reservoir quality (A and B). The new methods developed in this study can be applied to any carbonate formation to provide a trustworthy way to obtain a reservoir quality indicator linked to the petrophysical heterogeneity of the studied formation.

Mitigation of Fracturing Fluid Leak-Off and Subsequent Formation Damage Caused by Coal Fine Invasion in Fractures: An Experimental Study

During the hydraulic fracturing process of coalbed methane (CBM) reservoirs, significant amounts of secondary coal fines are generated due to proppant grinding and crack propagation, which migrate with the fracturing fluid into surrounding fracture systems. To investigate whether coal fines can form plugs to reduce fluid leak-off during the hydraulic fracturing stage, we conducted physical simulation experiments on coal seam plugging and unplugging to demonstrate that coal fines indeed contribute to reducing fluid leak-off during hydraulic fracturing. We also explored the plugging mechanisms of coal fines under different concentrations and particle sizes in fracturing fluids, and revealed the damage law of coal fines of temporary plugging on reservoir permeability. Research results indicate the leak-off volume of fracturing fluids containing coal fines is lower than an order without coal fines, demonstrating a significant effect of coal fines in decreasing fluid leak-off. The temporary plugging rate of coal fines increases with higher concentrations and decreases with larger particle sizes, achieving rates exceeding 90%. The high temporary plugging effect of coal fines results from the superposition of internal and external filter cakes. Under conditions of small particle size and high concentration, the damage to fractures during the fine return process is minimized. Considering the potential damage of coal fines to propping fractures and wellbore, the concentration of coal fines in fracturing fluids should be kept relatively low while ensuring a high temporary plugging effect. Overall, these findings provide crucial insights into optimizing the temporary plugging performance of coal fines during the hydraulic fracturing stage and controlling their behavior during the fracturing fluid flow-back stage, thereby enhancing reservoir fracturing effectiveness and improving CBM production rates.